Recovering hydrocarbons from subterranean zones typically involves drilling wellbores.
Wellbores are made using surface-located drilling equipment which drives a drill string that eventually extends from the surface equipment to the formation or subterranean zone of interest. The drill string can extend thousands of feet or meters below the surface. The terminal end of the drill string includes a drill bit for drilling (or extending) the wellbore.
Bottom hole assembly (BHA) is the name given to the equipment at the terminal end of a drill string. In addition to a drill bit, a BHA may comprise elements such as: apparatus for steering the direction of the drilling (e.g. a steerable downhole mud motor or rotary steerable system); sensors for measuring properties of the surrounding geological formations (e.g. sensors for use in well logging); sensors for measuring downhole conditions as drilling progresses; one or more systems for telemetry of data to the surface; stabilizers; heavy weight drill collars; pulsers; and the like. The BHA is typically advanced into the wellbore by a string of metallic tubulars (drill pipe).
Modern drilling systems may include any of a wide range of mechanical/electronic systems in the BHA or at other downhole locations. Such electronics systems may be packaged as part of a downhole tool. A downhole tool may comprise any active mechanical, electronic, and/or electromechanical system that operates downhole. A downhole tool may provide any of a wide range of functions including, without limitation: data acquisition; measuring properties of the surrounding geological formations (e.g. well logging); measuring downhole conditions as drilling progresses; controlling downhole equipment; monitoring status of downhole equipment; directional drilling applications; measuring while drilling (MWD) applications; logging while drilling (LWD) applications; measuring properties of downhole fluids; and the like. A downhole tool may comprise one or more systems for: telemetry of data to the surface; collecting data by way of sensors (e.g. sensors for use in well logging) that may include one or more of vibration sensors, magnetometers, inclinometers, accelerometers, nuclear particle detectors, electromagnetic detectors, acoustic detectors, and others; acquiring images; measuring fluid flow; determining directions; emitting signals, particles or fields for detection by other devices; interfacing to other downhole equipment; sampling downhole fluids; etc. A downhole tool may be incorporated into a drill string section or provided in a probe that is suspended in a bore of a drill string.
A downhole tool may communicate a wide range of information to the surface by telemetry. Telemetry information can be invaluable for efficient drilling operations. For example, telemetry information may be used by a drill rig crew to make decisions about controlling and steering the drill bit to optimize the drilling speed and trajectory based on numerous factors, including legal boundaries, locations of existing wells, formation properties, hydrocarbon size and location, etc. A crew may make intentional deviations from the planned path as necessary based on information gathered from downhole sensors and transmitted to the surface by telemetry during the drilling process. The ability to obtain and transmit reliable data from downhole locations allows for relatively more economical and more efficient drilling operations.
Telemetry data may include data regarding a current orientation of a drill bit (sometimes called “tool face” data). Telemetry information may include data retrieved from sensors which monitor characteristics of the formations surrounding the well bore (“logging” data). Telemetry information may include information regarding the drilling itself (e.g. information regarding downhole vibration, characteristics of the wellbore being drilled, flow rate of drilling fluid, downhole pressure and the like).
There are several known telemetry techniques. These include transmitting information by generating vibrations in fluid in the bore hole (e.g. acoustic telemetry or mud pulse (MP) telemetry) and transmitting information by way of electromagnetic signals that propagate at least in part through the earth (EM telemetry). Other telemetry techniques use hardwired drill pipe, fibre optic cable, or drill collar acoustic telemetry to carry data to the surface.
Advantages of EM telemetry, relative to MP telemetry, include generally faster baud rates, increased reliability due to no moving downhole parts, high resistance to lost circulating material (LCM) use, and suitability for air/underbalanced drilling. An EM system can transmit data without a continuous fluid column; hence it is useful when there is no drilling fluid flowing. This is advantageous when a drill crew is adding a new section of drill pipe as the EM signal can transmit information (e.g. directional information) while the drill crew is adding the new pipe.
A typical arrangement for electromagnetic telemetry uses parts of the drill string as an antenna. The drill string may be divided into two conductive sections by including an insulating joint or connector (a “gap sub”) in the drill string. The gap sub is typically placed at the top of a BHA such that metallic drill pipe in the drill string above the BHA serves as one antenna element and metallic sections in the BHA serve as another antenna element. Electromagnetic telemetry signals can then be transmitted by applying electrical signals between the two antenna elements.
The EM telemetry signals typically comprise very low frequency AC signals applied in a manner that encodes information for transmission to the surface. Low frequencies are used because higher frequency signals are attenuated much more strongly than low frequency signals. The electromagnetic signals may be detected at the surface, for example by measuring electrical potential differences between the drill string or a metal casing that extends into the ground and one or more ground conductors.
Typically, a signal receiver is provided at or near the surface of the formation. The signal receiver is in turn connected by signal links to ground conductors placed in different areas around the formation and to a blowout preventer at the top of the drill string or metal casing. A plurality of ground conductors is typically used.
Through its electrical connections to ground conductors and the blowout preventer, the signal receiver may measure the variable potential differences resulting from the signals imposed between upper and lower parts by a signal generator coupled to the downhole tool. The signals imposed by the signal generator may have amplitudes of ones, tens or hundreds of volts, for example. The signals received at signal receiver are typically in the millivolt range or lower. Received signals may be discriminated from background electrical noise by taking account of the fact that the signals transmitted by signal generator have known frequency or frequencies. Therefore, information can be sent from a downhole location by way of a signal generator to the signal receiver.
The detection of EM telemetry signals through measurement of the difference in the electric potential between the drill rig and various surface grounding rods located in the formation surrounding the drill rig is described in U.S. Pat. No. 4,160,970.
There is a demand for reliable and effective telemetry. There is a particular need for improved testing, diagnosing, and managing connections between ground conductors and signal receivers in EM telemetry systems.